Process for treating crude oil using hydrogen in a special unit

ABSTRACT

A process is provided for treating crude oil to visbreak and/or upgrade such oil using hydrogen gas. The process includes the steps of introducing hydrogen into a heated stream of crude oil or partially upgraded crude oil and mixing such introduced hydrogen with the oil to achieve intimate dispersion of hydrogen to enhance thereby visbreaking and/or upgrading.

FIELD OF INVENTION

This invention relates to the upgrading of crude oil by: (i) destructivehydrogenation which reduces its specific gravity and viscosity, and (ii)non-destructive hydrogenation which improves the product quality byremoving sulfur, nitrogen, and oxygen.

BACKGROUND OF INVENTION

This invention finds application in treatment and upgrading of heavycrude oil and bitumen. These materials are commonly very viscous anddense liquid scontaining various concentrations of sulfur. Pipelinecompanies penalize heavy crude oil producers for the quality of crudeoil produced. These penalties can result in price deductions fromundesirable oil properties related to density, sulfur content, andviscosity.

A common practice by heavy oil producers is to add condensate (lowboiling liquid hydrocarbon) to the produced crude oil to meet viscosityspecifications for pipeline shipment. The requirement to add acondensate reduces the profit margin per barrel of oil produced. Anotheralternative is to treat and upgrade the crude oil before injecting itinto pipelines. Current treatment and upgrading techniques have beenshown to be only economically viable in large plant capacities.Furthermore, these technologies are based on producing a variety ofproducts. One of the advantages of this invention is providing a methodof minimizing and/or eliminating price deductions related to producedcrude oil quality and focuses on producing a single product stream thatcan be transported via the pipeline in small and large plant capacities.

Upgrading and treatment technologies, such as described in U.S. Pat.Nos. 4,294,686 and 5,069,775 and Canadian Patent 1,191,471 can beclassified as either: (i) carbon rejection processes, (ii) non-carbonrejection processes, or (iii) combinations of either processes. Carbonrejection processes are based on removing a portion of the crude oil asa solid or semi-solid substance called coke. Coke production is commonlyaccompanied with gases being produced from severe cracking reactions.Usually the impurities remain in the coke. Poor process economics aretypical for carbon rejection processes because liquid yields aregenerally between 65% and 80%. Non-carbon rejection processes arecommonly known as visbreaking (viscosity breaking—an operation toreduce), reforming, alkylation, polymerization, and hydrogen-refiningmethods. These non-carbon rejection processes result in liquid yieldsbetween 90% to 105%.

This invention is based on the following design criteria:

-   -   1. Small and large plant capacities that are of modular        construction, which can be deployed at field production        batteries to produce a single liquid product stream, and    -   2. A process designed to produce highly favorable process        economics by (i) maximizing product yields, (ii) minimizing        product viscosity, (iii) minimizing density, (iv) maximizing the        removal of contaminants, (v) minimizing capital equipment costs,        and (vi) minimizing processing costs.        Heavy crude oils are generally hydrogen deficient and are best        amendable for treatment with hydrogenation processes. A        hydrogenation process best satisfies the design criteria.        Hydrogenation processes for refining are classified as        destructive or nondestructive techniques. Crude oil exists as        homologous fractions that have boiling point ranges between        36° C. (97° F.) to 553° C. (1027° F.). The denser and larger        boiling point fractions are composed of long chain hydrocarbons.        To minimize density and viscosity, these long chain hydrocarbon        need to be broken into fragments. The fragmentation is        accomplished by cracking reactions. Generally, cracking        reactions occur at temperatures above 343° C. (650° F.).        Destructive hydrogenation is achieved by cracking the liquid        hydrocarbon molecular bonds and accompanied by hydrogen        saturation of the fragments to create stable lower boiling point        products, such as described in Canadian patent 1,191,471. This        technique employs moderate processing conditions and        high-pressure hydrogen that minimizes polymerization and        condensation which minimizes coking. Destructive hydrogenation        processes generally are operated at pressures from 1,000 psi to        3,000 psi and at a temperature in the order of 538° C. (1000°        F.). Non-destructive hydrogenation is generally used for the        purpose of improving product quality without appreciable        alterations of the boiling point range or density. Milder        processing conditions are employed for the removal of        undesirable products. These undesirable products include sulfur,        nitrogen, oxygen, olefins, and heavy metals.

Other examples of upgrading and viscosity reduction processes involvingthe use of hydrogen at high temperatures and pressures and always undercatalytic conditions are described in German application 1,933,857;Canadian patent 1,272,461; U.S. Pat. No. 3,598,722, and WO 97/29841.

SUMMARY OF INVENTION

The invention in accordance with an aspect therefore provides a method,which injects either, a low or high-pressure hydrogen containing gastreatment stream into either a low or high-pressure hydrocarbon stream.In the case of a low-pressure gas treatment stream being injected into ahigh-pressure hydrocarbon stream, the low-pressure stream is injectedinto the stream without the use of mechanical energy such as a gasinjection pump or compressor, thereby reducing capital equipment costs.In the destructive hydrogenation step, the process provides a method ofsaturating the liquid hydrocarbon with hydrogen or other gases abovenormal saturation levels. An aspect of the process is to preheat thehydrogen and disperse the hydrogen or other gases at a near molecularlevel into the liquid hydrocarbon stream. These aspects and others allowthe operating conditions to be less severe than conventionalhydrogenation processes. These conclusions are supported with evidenceas provided in the summary of experimental data.

In accordance with an aspect of the invention a process is provided fortreating crude oil to reduce viscosity and/or upgrade such oil usinghydrogen gas. The process comprises the steps of introducing a hydrogencontaining stream to a heated stream of crude oil or partially upgradedcrude oil and mixing such introduced hydrogen with the oil to achieveintimate dispersion of hydrogen molecules in said oil stream to providehydrogenation reactions with oil hydrocarbons.

In accordance with another aspect of the invention, a process isprovided for treating crude oil or partially upgraded crude oil toreduce viscosity and/or upgrade such oil using hydrogen treatment underreactive conditions, The process comprises:

-   -   i) heating feed stream of crude oil to about 38° C. (100° F.) to        about 316° C. (600° F.) and introducing a side stream containing        hydrogen to the feed stream and mixing the streams to achieve        uniform dispersion of hydrogen molecules in the oil stream,        dividing the mixed stream and introducing a minor stream to a        primary vessel to achieve separation of volatile light ends from        hydrotreated heavier ends and introducing a major portion to a        stream returned from a primary hydrogen treatment zone and        before introduction to the primary vessel to the quench hydrogen        treatment and minimize coke production in the primary vessel,    -   ii) removing light volatiles from the primary vessel and        directing them to a secondary vessel for further separation,    -   iii) removing heavy non-volatiles from the primary vessel and        directing them to said primary hydrogen treatment loop where        hydrogen is introduced to the stream of heavy non-volatiles,        mixed and heated to an elevated temperature of about 343° C.        (650° F.) to about 510° C. (950° F.) followed by additional        mixing to enhance hydrogen reactions, returning the stream to        the primary vessel with the introduction of the major portion of        treated crude oil stream to quench any coke forming reactions        before introduction to the primary vessel.

BRIEF DESCRIPTION OF THE DRAWINGS

Preferred embodiments of the invention are shown in the drawingswherein:

FIG. 1 is a flow diagram of the process in accordance with a aspect ofthe invention.

DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS OF THE INVENTION

The markets available to use this invention may for example be regionsthat produce heavy oil. These include markets in Canada, Venezuela,United States, Africa, and other international production regions. Oneof the largest target market includes the field in Venezuela. The heavyoil reserves of the Oil Belt of Venezuela have been estimated to be 1.1trillion barrels. An upgrading technology represents a tremendous marketadvantage in the heavy oil production regions of the world. The processof this invention is also capable of treating the crude oil stream toremove sulfur based compounds, nitrogen based compounds and metalliccompounds. This invention also represents a significant improvement inconventional refining practices. Refineries could easily employ thistechnology to improve hydroprocessing techniques.

The features of this invention provide improved benefits in the upgraderprocess and higher quality product through destructive andnon-destructive hydrogenation. Various aspects of the process provideseveral features and advantages, which include:

Improved hydrogenation through mixing to achieve saturation of the feedmaterial with hydrogen,

Improved removal of lighter hydrocarbons by saturating the feedmaterials with recycle gas made by the process (under reduced partialpressure and improved gas diffusion),

Flashing and/or low pressure for removal of lighter components toincrease the effectiveness of hydrogenation,

The ability to operate at different operating temperatures and pressuresto produce a desired product,

Saturation of the undistilled portion of hydrocarbons with hydrogen(achieved by reducing the high-pressure limitations present inconventional hydrogenation and hence improved diffusion of hydrogen),

Injection of hydrogen at low pressure into a high pressure hydrocarbonstream,

Increased utilization of hydrogen (by minimizing hydrogen recycle andhydrogen addition rate),

Control of recycle rates to provide higher quality products (by means ofa variable-circulating ratio of undistilled to feed hydrocarbons),

Control of residence time to provide higher quality products,

Provide upgraded stable products,

Saturation of hydrocarbons with hydrogen to improved product quality(achieved by removing sulfur, nitrogen, oxygen, and heavy metalcomponents),

Flexible operating pressures parameters to provide desired productcondition.

Reduction of plant cost as compared to conventional processes (bylimiting the size of the equipment for hydrogenating hydrocarbons).

As shown in FIG. 1, the raw crude oil containing less than 0.5 volumepercent sediment and water is injected into the system through line 1 byuse of a variable rate feed pump 2 operated at pressures between 100 psito 2500 psi. A pulsation dampener 3 maintains constant pressureconditions downstream. The feed material is heated to relatively mildtemperatures to maintain a constant temperature between 38° C. (100° F.)to 316° C. (600° F.) at the outlet of heater 4. Heating of the liquidhydrocarbon stream is accomplished by means of direct or indirectheating. Hydrogen-rich product gas which may be a by-product of theprocess (such as described in U.S. Pat. Nos. 4,294,686 and 5,069,775)may be recycled into the system through line 40 into what can be aventuri, inductor, eductor, injector, or tee at point 7 receivingpreheated feed material from heater 4. A stream that is low pressure(i.e. less than 350 psi) is effectively induced into the liquidhydrocarbon stream by a venturi, inductor, or eductor. Whereas for highpressure (i.e. greater than 350 psi) the gas stream is effectivelyinjected into the liquid hydrocarbon stream using a tee or injector. Thetwo process streams are mixed to provide non-catalytic, non-destructivehydrogenation reactions using a mixing vessel or in line mixing device 8to thoroughly mix and disperse one process stream into the other stream.The mixer functions to disperse the hydrogen into the oil stream at ahighly efficient level to provide very fine bubbles in the oil stream.Such dispersion is usually at a saturation level and hence the reduceddemand for hydrogen. Although it is understood that, depending on thetype of mixer and the quantities of hydrogen, slightly less thansaturation, or saturation may also be achieved. Normal prior artprocesses use 3 to 5 times the required amount, as taught for example inpublished PCT application WO97/29841 where about 2000 ft.³ of H₂/barrelof oil to 10000 ft.³ of H₂/1\barrel of oil. The process of thisinvention uses considerably less, usually in the range of 15% to 30%excess more than the stoichiometric amount. Following mixing, additionalnon-destructive hydrogenation is accomplished in catalyst vessel 9filled with commercially available catalysts, such as described inCanadian patent 1,191,471 and WO97/29841. Catalyst vessel 9 may alsoserve to trap and remove any metals present in the raw feed material toprotect the catalyst in vessel 23. The catalyst may also be housed in areactor having a fixed bed, a mixing provision such as a stirredreactor, a fluidized bed or an ebullated bed to enhance distribution ofthe catalyst to enhance the catalytic conversion. If non-catalyticprocesses are only to be used, then catalyst vessel 9 can be by-passedusing line 10. Following mixing, multiple flow patterns can be taken atpoint 11. Control valves 12 and 13 can be manipulated to maintainprocess conditions and optimize process performance of the system.

A primary vessel 14 provides a means of removing the vaporized gascomponents from the liquid hydrocarbon. A vacuum may be applied tovessel 14 to increase flash yields. After the hydrogenated hydrocarbonmaterial introduced in line 42 has been flashed in vessel 14, theheavier ends are removed from vessel 14 through line 15 by the highpressure, high temperature, variable rate pump 16. Following pump 16,multiple flow patterns can be taken at point 17. A pulsation dampener 18is used after pumps 16 and 26 to maintain constant pressure conditions.At point 17 the heavier ends can be discharged directly by control valve27 into vessel 34 to achieve a desired treated feed material. Prior toentry into vessel 34 the treated quality oil in line 50 is cooled atheat removal device 28 and condensed in a secondary vessel 34.Alternatively, the stream can be and in most circumstances will berecycled for further hydroprocessing.

Hydrogen or hydrogen rich gases created from the process are introducedin line 5 and split after heating into lines 40 and 41. Process gasescan be used to increase hydrogen utilization. Hydrogen introduced inline 5 can be supplied at pressures as low as 50 psi to as high as 2500psi. Hydrogen or process gases are heated using heater 6 to maintain thegas temperature to minimize or prevent the cooling of hydrocarbonliquids that contact the gas stream. Following heating, multiple flowpatterns can be taken at point 43 Heavier ends removed by pump 16 arehydrogenated in the mixing vessel or in line mixing device 20 byintroduction of hydrogen or process gases in line 5 at point 19. The gasand liquid streams are combined at 19 using a venturi, inductor,eductor, injector, or tee. A low-pressure gas stream (less than 350 psi)is effectively induced into the liquid hydrocarbon stream by a venturi,inductor, or eductor. Where as high pressure gas stream (greater than350 psi) is effectively injected into the liquid hydrocarbon streamusing a tee or injector. The mixing vessel or in line mixing device 20is designed to mix and disperse a gas phase with a liquid phase toprovide non-catalytic, non-destructive hydrogenation reactions.Following hydrogenation of the heavier ends the stream is heated usingheater 21. The heat-input device 21 is used to increase the temperatureof the combined stream from 20 to a set point between 343° C. (650° F.)to 510° C. (950° F.). Heater 21 also provides for cracking of heavierhydrocarbon components into smaller components. Maintaining pressuresabove 350 psi within this line and the addition of hydrogen to stream 15eliminates plugging of heater 21 due to coking. Following heatingadditional mixing is provided by the mixing vessel or in line mixingdevice 22. The mixing vessel or device 22 is designed to mix anddisperse a gas phase with a liquid phase and to provide non-catalytic,destructive hydrogenation reactions. Inserted after this mixing step iscatalyst vessel 23 for additional destructive hydrogenation. Ifnon-catalytic processes are only to be used then catalyst vessel 23 canbe by-passed using line 24. Multiple flow patterns are provided for inthe system at point 25. The stream can be recycled in this primaryhydrogen treating loop using the high pressure, high temperature,variable rate pump 26 designed for a two-phase stream. Pump 26 can beused to change the residence time of the static mixers or devices 20 and22 during the destructive hydrogenation step.

In accordance with this invention the hydrogen gas or hydrogen richgases in lines 40 and 41 and the treated quenching stream in line 45 canbe injected at low or high pressure into the respective high pressurehydrocarbon stream to be further treated. The injection process iscapable of injecting a gas or other type of fluid at very low pressuresrelative to the main hydrocarbon stream pressure and at the same timeachieve excellent mixing at near molecular level. This aspect of theinvention may be accomplished by any suitable means, which by use of amixer is capable of saturating the main stream with the treatment gasabove normal saturation levels and doing so at lower temperature thanconventional temperatures. For example, a suitable venturi, inductor, oreductor may be used at each injection point.

Hydrogen gas injection provides the benefits of non-destructivehydroprocessing and the increased flashing through stripping. Improvedflashing in vessel 14 may be achieved by use of a blower 46 or othersuitable pump in line 37. Optionally a blower 46 is provided to draw avacuum in the vessel 34, which in turns draws a vacuum in lines 32 and47 on into vessel 14. The feed material exits treatment at 48 and into atee at 11 where the flow is partitioned into two streams at lines 45 and49. Two control valves 12 and 13 maintain the flow volume through tee11. Signals to these control valves are provided by pressure andtemperature measurements. These control valves maintain the pressure onthe upstream hydrocarbons in line 48 and provide a method of quenchingthe hot hydrocarbons exiting the hydrogenation process in line 44.

Vessel 14 can be operated at about atmospheric pressure or under avacuum to remove the lighter ends that may interfere with thehydrogenation step. Operating the vessel at about atmospheric pressureis a significant advantage over prior art processes because the vesseldoes not have to meet pressurized vessel codes. The hydrocarbon liquidsare recycled by pump 16 from the flash step into the hydrogenation stepat desired ratios as compared to the feed pump rate. Pressure ismaintained on the system by the use of control valves 31 and 51.Chemical reactions in line 44 are quenched at process point 29 by theintroduction of the major preheated feed stream 45 to prevent theformation of coke. The quenched stream is mixed using mixing vessel oran in line mixing device 30 designed to mix a colder liquid phase with awarmer liquid phase that is capable of providing non-catalytic,destructive hydrogenation reactions. Large portions of the heavier endsthat are not flashed in vessel 14 are recycled through pump 16 toprovide further hydroprocessing or exit the system through line 50.Lighter ends from flashing in vessel 14, normally operated at about 500°F., are removed by line 32 where the product is condensed and cooledusing heat exchanger 33 and discharged into vessel 34. Mist andentrained liquids from vessel 34 are condensed and cooled in heatremoval device 35 and captured in vessel 36. Liquids that are condensedin vessel 36 are returned to vessel 34. The combined product streamscondensed in or collected in vessel 34 are cooled and collected usingvariable-rate transfer pump 38 to provide product in line 39. Thehydrogen rich hydrocarbon gas stream in line 37 may be used as treatmentgas in line 5.

SUMMARY OF EXPERIMENTAL DATA

An example of process data using the invention described herein isprovided. Typically, to achieve significant viscosity reductions andincreases in API gravity, conventional processing temperatures between454° C. (850° F.) to 510° C. (950° F.) are employed. As a result ofusing the invention described herein, Table 1 shows significantviscosity reductions and lighter product materials produced by thisinvention under very mild operating conditions with processingtemperatures not exceeding 402° C. (755° F.). Compared to prior artprocess which require catalyst, operating pressures usually in excess of2000 psi and operating temperatures 482° C. (900° F.) or more. The feedstock was an Alberta heavy crude oil and relative to these analyses, hadan average API gravity of 12.7 and viscosity of 3808 cP @ 20° C. (68°F.).

TABLE 1 An Example of Preliminary Product Analyses obtained from theInvention Viscosity Temperature API increase Reduction¹ ° F. % % 735 N/A13.94 745 0.79 36.73 750 4.00 50.75 755 9.37 67.88 N/A-not available1-Measured at 20° C. (68° F.)

Various embodiments of the invention have been described herein indetail. It is appreciated by those skilled in the art that variationsmay be made thereto without departing from the spirit of the inventionor the scope of the appended claims.

1. A process for treating crude oil or partially upgraded crude oil toreduce viscosity or upgrade such oil using hydrogen treatment underreactive conditions, said process comprising: i) heating feed stream ofcrude oil to about 38° C. to about 316° C. and introducing to said feedstream a first heated side stream containing hydrogen, and mixing saidfeed and side streams to produce a mixed stream having uniformdispersion of hydrogen molecules in said mixed stream; ii) dividing saidmixed stream into a minor mixed stream and a major mixed stream,introducing said minor mixed stream to a primary separating vessel toachieve separation of volatile light ends from hydrotreated heavierends; iii) introducing to said major mixed stream, prior to entry intosaid primary vessel, a mixed heavy stream returned from a primaryhydrogen treatment zone to quench hydrogen treatment and minimize cokeproduction in said primary vessel; iv) removing volatiles from saidprimary vessel and directing them to a secondary vessel for furtherseparation; v) removing heavy non-volatiles from said primary vessel anddirecting said heavy non-volatiles to a primary hydrogen treatment loopwhere a second heated side stream containing hydrogen is introduced andmixed into said heavy non-volatiles to produce said mixed heavy stream,said mixed heavy stream being heated to an elevated temperature of about343° C. to about 510° C. followed by additional mixing to enhancehydrogen reactions; and vi) combining said mixed heavy stream with saidmajor mixed stream prior to entry into said primary vessel to quench anycoke forming reactions before introduction to said primary vessel.
 2. Aprocess of claim 1, wherein a minor portion of said heavy non-volatilesfrom said primary vessel is introduced to said secondary vessel.
 3. Aprocess of claim 1, wherein a portion of said heavy non-volatiles insaid primary hydrogen treatment loop is recycled in said loop forfurther treatment before delivery to said primary vessel.
 4. A processof claim 1, wherein optional catalyst treatment is provided downstreamof each point of hydrogen introduction to enhance hydrogenation ofcracked hydrocarbons.
 5. A process of claim 1, wherein at least one ofsaid first and second side streams containing hydrogen are introduced atpressures ranging from about 50 psi to about 2500 psi.
 6. A process ofclaim 1, wherein said primary hydrogen treatment loop comprises a pumpwith a dampener to recycle a portion of said mixed heavy stream forfurther upgrading.
 7. A process of claim 4, wherein said catalyst isprovided in a fixed bed or a stirred reactor, a fluidized bed reactor oran ebullated catalyst bed reactor.
 8. A process of claim 1, wherein saidprimary vessel is operated at about 500° F. to flash off lighthydrocarbons.
 9. A process of claim 1, wherein said first and secondside streams containing hydrogen are introduced to provide astoichiometric excess of hydrogen of up to 30%.
 10. process of claim 1,wherein said primary and secondary vessels are operated at a vacuumrelative to atmospheric pressure.
 11. A process of claim 10, whereinvalves are provided upstream and downstream of each said vessel topermit the vessels to operate at said vacuum.
 12. A process of claim 1,wherein a blower is provided downstream of said secondary vessel to drawoff said volatile light ends and develop a vacuum in said primary vesselto enhance flashing off of light ends.
 13. A process of claim 1, whereinsaid introducing to said feed stream a first heated side streamcontaining hydrogen removes sulphur-based compounds, nitrogen-basedcompounds and metallic compounds.
 14. A process of claim 1, wherein saidprimary hydrogen treatment loop is maintained at a pressure above 350psi to minimize coking at said elevated temperature where cracking,hydrogenation, or both, of hydrocarbons occur.